Electrically conductive oil-based fluids

ABSTRACT

At least one petroleum coke may be added to an oil-based fluid to improve the electrical conductivity of the oil-based fluid. The oil-based fluid may be a drilling fluid, a completion fluid, a drill-in fluid, a stimulation fluid, a servicing fluid, and combinations thereof. In a non-limiting embodiment, the downhole fluid composition may be circulated in a subterranean reservoir wellbore.

CROSS-REFERENCE TO RELATED APPLICATION

This application claims the benefit of U.S. Provisional patentapplication Ser. No. 62/027,008 filed Jul. 21, 2014, incorporated hereinby reference in its entirety.

TECHNICAL FIELD

The present invention relates to a fluid composition and a method forimproving the electrical conductivity of an oil-based fluid that may bea drilling fluid, a completion fluid, a drill-in fluid, a stimulationfluid, and combinations thereof by adding at least one petroleum coke tothe oil-based fluid.

BACKGROUND

Fluids used in the drilling, completion, stimulation, and remediation ofsubterranean oil and gas wells are known. It will be appreciated thatwithin the context herein, the term “fluid” also encompasses “drillingfluids”, “completion fluids”, “workover fluids”, “servicing fluids”,“stimulation fluids”, and “remediation fluids”.

Drilling fluids are typically classified according to their base fluid.In water-based fluids, solid particles are suspended in a continuousphase consisting of water or brine. Oil can be emulsified in the water,which is the continuous phase. “Water-based fluid” is used herein toinclude fluids having an aqueous continuous phase where the aqueouscontinuous phase can be all water or brine, an oil-in-water emulsion, oran oil-in-brine emulsion. Brine-based fluids, of course are water-basedfluids, in which the aqueous component is brine.

Oil-based fluids are the opposite or inverse of water-based fluids.“Oil-based fluid” is used herein to include fluids that are completelyoil, fluids having a non-aqueous continuous phase where the non-aqueouscontinuous phase is all oil, a non-aqueous fluid, a water-in-oilemulsion, a water-in-non-aqueous emulsion, a brine-in-oil emulsion, or abrine-in-non-aqueous emulsion. In oil-based fluids, solid particles aresuspended in a continuous phase consisting of oil or another non-aqueousfluid. Water or brine can be emulsified in the oil; therefore, the oilis the continuous phase. In oil-based fluids, the oil may consist of anyoil or water-immiscible fluid that may include, but is not limited to,diesel, mineral oil, esters, refinery cuts and blends, or alpha-olefins.Oil-based fluid as defined herein may also include synthetic-basedfluids or muds (SBMs), which are synthetically produced rather thanrefined from naturally occurring materials. Synthetic-based fluids ofteninclude, but are not necessarily limited to, olefin oligomers ofethylene, esters made from vegetable fatty acids and alcohols, ethersand polyethers made from alcohols and polyalcohols, paraffinic and/oraromatic hydrocarbons, alkyl benzenes, terpenes and other naturalproducts and mixtures of these types.

For some applications, in particular for the use of some wellboreimaging tools, it is important to reduce the electrical resistivity(which is equivalent to increasing the electrical conductivity) of theoil-based fluid as the electrical conductivity of the fluids has adirect impact on the image quality. Certain resistivity logging tools,such as high resolution LWD tool STARTRAK™, available from Baker HughesInc, require the fluid to be electrically conductive to obtain the bestimage resolution. Water-based fluids, which are typically highlyelectrically conductive with a resistivity less than about 100 Ohm-m,are typically preferred for use with such tools in order to obtain ahigh resolution from the LWD logging tool.

However, oil based fluids are preferred in certain formation conditions,such as those with sensitive shales, or high pressure high temperature(HPHT) conditions where corrosion is abundant. Oil-based fluids are achallenge to use with high resolution resistivity tool, e.g. STARTRAK™,because oil-based fluids have a low electrical conductivity (i.e. highresistivity). It would be highly desirable if fluid compositions andmethods could be devised to increase the electrical conductivity of theoil-based or non-aqueous-liquid-based drilling, completion, production,and remediation fluids and thereby allow for better utilization ofresistivity logging tools.

There are a variety of functions and characteristics that are expectedof completion fluids. The completion fluid may be placed in a well tofacilitate final operations prior to initiation of production.Completion fluids are typically brines, such as chlorides, bromides,formates, but may be any non-damaging fluid having proper density andflow characteristics. Suitable salts for forming the brines include, butare not necessarily limited to, sodium chloride, calcium chloride, zincchloride, potassium chloride, potassium bromide, sodium bromide, calciumbromide, zinc bromide, sodium formate, potassium formate, ammoniumformate, cesium formate, and mixtures thereof.

Chemical compatibility of the completion fluid with the reservoirformation and fluids is key. Chemical additives, such as polymers andsurfactants are known in the art for being introduced to the brines usedin well servicing fluids for various reasons that include, but are notlimited to, increasing viscosity, and increasing the density of thebrine. Water-thickening polymers serve to increase the viscosity of thebrines and thus retard the migration of the brines into the formationand lift drilled solids from the wellbore. A regular drilling fluid isusually not compatible for completion operations because of its solidscontent, pH, and ionic composition. Completion fluids also help placecertain completion-related equipment, such as gravel packs, withoutdamaging the producing subterranean formation zones. Modifying theelectrical conductivity and resistivity of completion fluids may allowthe use of resistivity logging tools for facilitating final operations.

A stimulation fluid may be a treatment fluid prepared to stimulate,restore, or enhance the productivity of a well, such as fracturingfluids and/or matrix stimulation fluids in one non-limiting example.Stimulation fluids typically contain an acid or a solvent.

Servicing fluids, such as remediation fluids, workover fluids, and thelike, have several functions and characteristics necessary for repairinga damaged well. Such fluids may be used for breaking emulsions alreadyformed and for removing formation damage that may have occurred duringthe drilling, completion and/or production operations. The terms“remedial operations” and “remediate” are defined herein to include alowering of the viscosity of gel damage and/or the partial or completeremoval of damage of any type from a subterranean formation. Similarly,the term “remediation fluid” is defined herein to include any fluid thatmay be useful in remedial operations.

Before performing remedial operations, the production of the well mustbe stopped, as well as the pressure of the reservoir contained. To dothis, any tubing-casing packers may be unseated, and then servicingfluids are run down the tubing-casing annulus and up the tubing string.These servicing fluids aid in balancing the pressure of the reservoirand prevent the influx of any reservoir fluids. The tubing may beremoved from the well once the well pressure is under control. Toolstypically used for remedial operations include wireline tools, packers,perforating guns, flow-rate sensors, electric logging sondes, etc.

A drill-in fluid may be used exclusively for drilling through thereservoir section of a wellbore successfully, which may be a long,horizontal drainhole. The drill-in fluid may minimize damage andmaximize production of exposed zones, and/or facilitate any necessarywell completion. A drill-in fluid may be a fresh water or brine-basedfluid that contains solids having appropriate particle sizes (saltcrystals or calcium carbonate) and polymers. Drill-in fluids may beaqueous or non-aqueous. Filtration control additives and additives forcarrying cuttings may be added to a drill-in fluid.

It would be desirable if the aforementioned fluid compositions andmethods for using such fluids could be tailored to improve theelectrical conductivity of drilling fluids, completion fluids,stimulation fluids, drill-in fluids, and servicing fluids, and therebyenhance the performance of downhole tools, such as resistivity loggingtools in one non-limiting example.

SUMMARY

There is provided, in one non-limiting form, a downhole fluidcomposition that includes an oil-based fluid and at least one petroleumcoke in particle form. The oil-based fluid may be or include a drillingfluid, a completion fluid, a drill-in fluid, a stimulation fluid, aservicing fluid, and combinations thereof.

In an alternative embodiment of the downhole fluid composition, thepetroleum coke, in particle form, may be present in the downhole fluidcomposition in an amount ranging from about 0.05 wt % to about 25 wt %.The downhole fluid composition may also include a surfactant in aneffective amount to suspend the petroleum coke in the oil-based fluid.

In another non-limiting form, a method may include circulating adownhole fluid composition into a subterranean reservoir wellbore. Thedownhole fluid composition may be or include an oil-based fluid, such asdrilling fluid, a completion fluid, a drill-in fluid, a stimulationfluid, a servicing fluid, and combinations thereof. The downhole fluidcomposition may include at least one petroleum coke in an effectiveamount to improve the electrical conductivity of the downhole fluid. Theat least one petroleum coke is in particle form.

In an alternative form of the method, the method may include adding aneffective amount of at least one petroleum coke to an oil-based fluid toform a downhole fluid composition having improved electrical properties.The oil-based fluid may be selected from the group consisting of adrilling fluid, a completion fluid, a drill-in fluid, a stimulationfluid, a servicing fluid, and combinations thereof. The at least onepetroleum coke is in particle form and is present in an amount effectiveto improve electrical conductivity of the oil-based fluid. The methodmay also include adding a surfactant to the oil-based fluid in an amounteffective to suspend the at least one petroleum coke in the oil-basedfluid. The at least one petroleum coke and at least one surfactant maybe added to the oil-based fluid in any order.

Petroleum coke appears to improve the electrical conductivity of thedownhole fluid composition.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a graph illustrating the resistance measurements of twodifferent mineral oil formulations where each resistance measurementcorrelates to an amount of the coke within each sample;

FIG. 2 is a graph illustrating the resistance measurements of fourdifferent mineral oil formulations where each formulation has adifferent type and/or amount of coke therein; and

FIG. 3 is a graph illustrating the resistance measurements of fourdifferent mineral oil formulations where each formulation has adifferent type and/or amount of coke therein.

DETAILED DESCRIPTION

It has been discovered that adding at least one type of petroleum coketo an oil-based fluid may give the oil-based fluid antistatic propertiesby increasing the electrical conductivity of the oil-based fluid.Non-limiting examples of such oil-based fluids may be or includeplastics, ink, paint, downhole fluids, and combinations thereof.

The downhole fluid composition may improve the use of a downhole tool,such as a resistivity logging tool in a non-limiting example. Thesetools are typically only used in aqueous fluids, e.g. water-basedfluids, because resistivity-logging tools require the fluid in thewellbore to be electrically conductive. The petroleum coke and/orparticles, mentioned below, may be added or dispersed into at least onephase of the oil-based fluid, such as the continuous phase in anon-limiting embodiment.

The final electrical conductivity of the downhole fluid composition maybe determined by the content and the inherent properties of thedispersed phase content, which may be tailored to achieve desired valuesof electrical conductivity. The final resistivity (inverse of electricalconductivity) of the downhole fluid composition may range from about0.02 ohm-m independently to about 1,000,000 ohm-m in one non-limitingembodiment. In an alternative embodiment, the resistivity may range fromabout 0.2 ohm-m independently to about 10,000 ohm-m, or from about 2ohm-m independently to about 1,000 ohm-m. Achieving this range ofelectrical conductivity within an oil-based fluid represents a decreaseof 6-9 orders of magnitude as compared with the electrical conductivityof typical oil-based fluids absent the petroleum coke. As used hereinwith respect to a range, “independently” means that any threshold may beused together with another threshold to give a suitable alternativerange, e.g. about 0.02 ohm-m independently to about 0.2 ohm-m is alsoconsidered a suitable alternative range.

The petroleum coke may be present in the downhole fluid composition inan amount effective to improve the performance of a downhole tool ascompared to an otherwise identical fluid absent the petroleum coke.Alternatively, the amount of the petroleum coke within the totaldownhole fluid composition may range from about 0.05 wt % independentlyto about 25 wt % based on the total fluid composition, or from about 1wt % independently to about 10 wt % in another non-limiting embodiment.The average particle size of the petroleum coke particles may range fromabout 10 nm independently to about 1,000 microns, alternatively fromabout 500 nm independently to about 500 microns, or from about 1 micronindependently to about 100 microns in another non-limiting embodiment.

In a non-limiting embodiment, the petroleum coke may be or includecalcined petroleum coke, green coke, anode-grade coke, coke treated witha metallic salt, and combinations thereof. Petroleum coke (also referredto as pet coke or petcoke) is a carbonaceous solid derived from oilrefinery coker units or other cracking processes. Petroleum coke mayalso be derived from coal. The raw coke or unprocessed coke is known asgreen coke, which may come directly from a coker unit. The green cokemay be further processed by removing moisture and/or residual volatilehydrocarbons from the coke, which is also known as ‘calcining’ the coke,and process coke via this method is known as calcined coke. One methodof calcining involves a rotary kiln in a non-limiting embodiment. Thecalcined petroleum coke may be further processed to produce needle oranode coke having desired shape and physical properties.

In a non-limiting embodiment, the petroleum coke within the downholefluid composition is calcined coke; alternatively, the petroleum cokewithin the downhole fluid composition is a combination of calcined coke,green coke, anode-grade coke, and/or coke treated with a metallic salt.The calcined petroleum coke and/or anode grade coke may improve theelectrical conductivity of the downhole fluid, while the green cokeand/or metallic salt treated coke may aid in controlling fluid loss, actas an anti-seepage additive, may act as a lubricant, or lost circulationmaterial, and combinations thereof.

In an alternative embodiment, the petroleum coke may be treated with ametallic salt. The metallic salt treatment may occur by spraying ametallic salt solution onto the petroleum coke prior to the calciningprocess of the coke. The metal portion of the salt may be or include,but is not limited to iron, magnesium, titanium, molybdenum, nickel,manganese, and combinations thereof. Such salts may be or include, butare not limited to metal halides, metal nitrites, metal sulfates, metaloxides, quaternary ammonium salts (e.g. tetraalkyl ammonium halides in anon-limiting embodiment), metal nitrates, metal sulfonates, andcombinations thereof. The amount of metal present in the metallic saltsolution may range from about 0.01 wt % independently to about 5 wt %,or from about 0.1 wt % independently to about 1 wt %. In a non-limitingembodiment, the metallic salt treated coke may be an additive to theoil-based fluid to improve a property, such as but not limited toanti-seepage, lost circulation or fluid loss, decreasing sulfur speciespresent in the oil-based fluid, and combinations thereof.

In a non-limiting embodiment, the downhole fluid composition may includecarbon black agglomerates, carbon black nanoparticles, and combinationsthereof; unless otherwise specified, ‘carbon black’ refers to bothcarbon black nanoparticles and micron-sized carbon black particles.Carbon black may be or include acetylene black, channel black, furnaceblack, lamp black, thermal black, and the like. Carbon black is amaterial produced by the incomplete combustion of heavy petroleumproducts, such as but not limited to, FCC tar, coal tar, ethylenecracking tar, vegetable oil, and combinations thereof. Carbon black hasa high surface-area-to-volume ratio because of its paracrystallinecarbon structure.

In another non-limiting embodiment, the downhole fluid composition mayinclude a second type of nanoparticles different from the carbon blacknanoparticles, such as but not limited to, graphite nanoparticles,graphene nanoparticles, graphene platelets, fullerenes, nanotubes,nanorods, nanoplatelets, and combinations thereof. In a non-limitingembodiment, the combination of the petroleum coke, carbon black, and/orsecond nanoparticles, may synergistically improve the electricalconductivity of the downhole fluid.

‘Second nanoparticles’ are defined herein to be nanoparticles that aredifferent from the carbon black nanoparticles; however, the secondnanoparticles may be present in the downhole fluid composition in theabsence of carbon black nanoparticles. Said differently, the notation of‘second’ does not imply that the second nanoparticles are added to thefluid after something else has been added to the fluid ‘first’, forexample, the second nanoparticles may be added to the fluid as the firstadditive, or the only additive.

The second nanoparticles may be or include nanotubes, nanorods,fullerenes, graphene, graphite nanoparticles, nanoplatelets, andcombinations thereof. In a non-limiting embodiment, the secondnanoparticles are electrically conductive. In another non-limitingembodiment, the nanotubes, nanorods, and/or nanoplatelets may bemetallic, ceramic, or combinations thereof in an alternative embodiment.In one non-limiting embodiment, the nanotubes are carbon nanotubes. Theamount of second nanoparticles within the downhole fluid composition mayrange from about 0.0001 wt % independently to about 15 wt % to modifythe electrical conductivity of the fluid. In a non-limiting embodiment,the second nanoparticles may be added in an amount ranging from about0.001 wt % independently to about 5 wt %, alternatively from about 0.01wt % independently to about 1 wt %.

The second nanoparticles may be functionally modified by a mechanism toform a functionalized nanoparticle. In a non-limiting embodiment, thefunctional modification improves the electrical conductivity of thesecond nanoparticles. The functional modification may be or include, butis not limited to a chemical modification, a covalent modification, aphysical modification, a surface modification, and combinations thereof.Thus, ‘functionalized nanoparticles’ are defined herein to be thenanoparticle having an increased or decreased functionality, and the‘functional modification’ is the process by which the nanoparticle hashad a particular functionality added, increased or decreased. Thefunctionalized nanoparticles may have different functionalities thannanoparticles that have not been functionally modified. In anon-limiting embodiment, the functional modification of the secondnanoparticles may improve the dispersibility of the second nanoparticlesin an oil-based fluid by stabilizing the second nanoparticles insuspension, which avoids undesirable flocculation as compared withotherwise identical second nanoparticles that have not been functionallymodified. In one non-limiting embodiment of the invention, it isdesirable that the conductivity properties of the fluid be uniform,which requires the distribution of the second nanoparticles and/orcarbon black to be uniform. If the second nanoparticles and/or carbonblack flocculate, drop out, or precipitate, the electrical conductivityof the fluid may change.

Graphene is an allotrope of carbon having a planar sheet structure thathas sp²-bonded carbon atoms densely packed in a 2-dimensional honeycombcrystal lattice. The term “graphene” is used herein to include particlesthat may contain more than one atomic plane, but still with a layeredmorphology, i.e. one in which one of the dimensions is significantlysmaller than the other two, and also may include any graphene that hasbeen functionally modified. The structure of graphene is hexagonal, andgraphene is often referred to as a 2-dimensional (2-D) material. The 2-Dmorphology of the graphene nanoparticles is of utmost importance whencarrying out the useful applications relevant to the graphenenanoparticles. The applications of graphite, the 3-D version ofgraphene, are not equivalent to the 2-D applications of graphene. Thegraphene may have at least one graphene sheet, and each grapheneplatelet may have a thickness no greater than 100 nm.

Graphene is in the form of one-atomic layer thick or multi-atomic layerthick platelets. Graphene platelets may have in-plane dimensions rangingfrom sub-micrometer to about 100 micrometers. This type of plateletshares many of the same characteristics as carbon nanotubes. Theplatelet chemical structure makes it easier to functionally modify theplatelet for enhanced dispersion in polymers. Graphene platelets provideelectrical conductivity that is similar to copper, but the density ofthe platelets may be about four times less than that of copper, whichallows for lighter materials. The graphene platelets may also be fifty(50) times stronger than steel with a surface area that is twice that ofcarbon nanotubes.

Graphene may form the basis of several nanoparticle types, such as butnot limited to the graphite nanoparticle, nanotubes, fullerenes, and thelike. Several graphene sheets layered together may form a graphitenanoparticle. In a non-limiting embodiment, a graphite nanoparticle mayhave from about 2 layered graphene sheets independently to about 20layered graphene sheets to form the graphite nanoparticle, or from about3 layered graphene sheets independently to about 25 layered graphenesheets in another non-limiting example. Graphite nanoparticles may rangefrom about 1 independently to about 50 nanometers thick, or from about 3nm independently to about 25 nm thick. The graphite nanoparticlediameter may range from about sub-micrometer independently to about 100micrometers.

Graphite nanoparticles are graphite (natural or synthetic) speciesdownsized into a submicron size by a process, such as but not limited toa mechanic milling process to form graphite platelets, or a laserablating technique to form a graphite nanoparticle having a sphericalstructure. The spherical structure may range in size from about 30 nmindependently to about 1000 nm, or from about 50 nm independently toabout 500 nm. In a non-limiting embodiment, the graphite platelets mayhave a 2D structure; whereas, the spherical graphite nanoparticles mayhave a 3D structure. Graphite nanoparticles have different chemicalproperties because of the layered graphene effect, which allows them tobe more electrically conductive than a single graphene sheet.

In another non-limiting embodiment, the graphene sheet may form asubstantially spherical structure having a hollow inside, which is knownas a fullerene. Such a cage-like structure allows a fullerene to havedifferent properties or features as compared to graphite nanoparticlesor graphene nanoparticle. For the most part, fullerenes are stablestructures, but a non-limiting characteristic reaction of a fullerene isan electrophilic addition at 6,6 double bonds to reduce angle strain bychanging a sp²-hydridized carbons into a sp³-hybridized carbon. Inanother non-limiting example, fullerenes may have other atoms trappedinside the hollow portion of the fullerene to form an endohedralfullerene. Metallofullerenes are non-limiting examples where one or twometallic atoms are trapped inside of the fullerene, but are notchemically bonded within the fullerene. Although fullerenes are notelectrically conductive alone, a functional modification to thefullerene may enhance a desired property thereto. Such functionalmodifications include, but are not necessarily limited to, chemicalmodifications, physical modifications, covalent modifications, and/orsurface modifications to form a functionalized fullerene.

In another non-limiting embodiment, the graphene sheet may form acylindrical sheet, which is known as a carbon nanotube or cylindricalfullerenes. Carbon nanotubes are defined herein as allotropes of carbonconsisting of one or several single-atomic layers of graphene rolledinto a cylindrical nanostructure. Nanotubes may be single-walled,double-walled or multi-walled; nanotubes may also be open-ended orclosed-ended. Nanotubes have high tensile strength, high electricalconductivity, high ductility, high heat conductivity, and relativechemical inactivity such that there are no exposed atoms that may beeasily displaced.

Electrical conductivity properties of graphene have been measured andcompare well with those of carbon nanotubes. The 2-D morphology,however, provides significant benefits when dispersed in complex fluids,such as multi-phasic fluids or emulsions. Unique to this application isthe engineering of the graphene dispersion within the non-conductingphase of the fluid, to achieve the desired properties.

In the present context, the second nanoparticles may have at least onedimension less than 50 nm, although other dimensions may be larger thanthis. In a non-limiting embodiment, the second nanoparticles may haveone dimension less than 30 nm, or alternatively less than 10 nm. In onenon-limiting instance, the smallest dimension of the secondnanoparticles may be less than 5 nm, but the length of the secondnanoparticles may be much longer than 100 nm, for instance 25,000 nm ormore. Such second nanoparticles would be within the scope of the fluidsherein.

Second nanoparticles typically have at least one dimension less than 100nm (one hundred nanometers). While materials on a micron scale haveproperties similar to the larger materials from which they are derived,assuming homogeneous composition, the same is not true of secondnanoparticles. An immediate example is the very large interfacial orsurface area per volume for second nanoparticles. The consequence ofthis phenomenon is a very large potential for interaction with othermatter, as a function of volume. For second nanoparticles, the surfacearea may be up to 1800 m²/g. Additionally, because of the very largesurface area to volume present with graphene, it is expected that inmost, if not all cases, much less proportion of graphene nanoparticlesneed be employed relative to micron-sized additives conventionally usedto achieve or accomplish a similar effect.

Nevertheless, it should be understood that surface-modified secondnanoparticles to form a surface-modified functionalized nanoparticle,which may find utility in the compositions and methods herein.“Surface-modification” is defined here as the process of altering ormodifying the surface properties of a particle by any means, includingbut not limited to physical, chemical, electrochemical or mechanicalmeans, and with the intent to provide a unique desirable property orcombination of properties to the surface of the nanoparticle, whichdiffers from the properties of the surface of the unprocessednanoparticle.

The second nanoparticles may be functionally modified to introducechemical functional groups thereon, for instance by reacting thegraphene nanoparticles with a peroxide such as diacyl peroxide to addacyl groups which are in turn reacted with diamines to give aminefunctionality, which may be further reacted. Functionalized secondnanoparticles are defined herein as those which have had their edges orsurfaces functionally modified to contain at least one functional groupincluding, but not necessarily limited to, sulfonate, sulfate,sulfosuccinate, thiosulfate, succinate, carboxylate, hydroxyl,glucoside, ethoxylate, propoxylate, phosphate, ethoxylate, ether,amines, amides, ethoxylate-propoxylate, an alkyl, an alkenyl, a phenyl,a benzyl, a perfluoro, thiol, an ester, an epoxy, a keto, a lactone, ametal, an organo-metallic group, an oligomer, a polymer, or combinationsthereof.

Introduction of functional groups by derivatizing the olefinicfunctionality associated with the second nanoparticles may be effectedby any of numerous known methods for direct carbon-carbon bond formationto an olefinic bond, or by linking to a functional group derived from anolefin. Exemplary methods of functionally modifying may include, but arenot limited to, reactions such as oxidation or oxidative cleavage ofolefins to form alcohols, diols, or carbonyl groups including aldehydes,ketones, or carboxylic acids; diazotization of olefins proceeding by theSandmeyer reaction; intercalation/metallization of a nanodiamond bytreatment with a reactive metal such as an alkali metal includinglithium, sodium, potassium, and the like, to form an anionicintermediate, followed by treatment with a molecule capable of reactingwith the metalized nanodiamond such as a carbonyl-containing species(carbon dioxide, carboxylic acids, anhydrides, esters, amides, imides,etc.), an alkyl species having a leaving group such as a halide (Cl, Br,I), a tosylate, a mesylate, or other reactive esters such as alkylhalides, alkyl tosylates, etc.; molecules having benzylic functionalgroups; use of transmetalated species with boron, zinc, or tin groupswhich react with e.g., aromatic halides in the presence of catalystssuch as palladium, copper, or nickel, which proceed via mechanisms suchas that of a Suzuki coupling reaction or the Stille reaction; pericyclicreactions (e.g., 3 or 4+2) or thermocyclic (2+2) cycloadditions of otherolefins, dienes, heteroatom substituted olefins, and combinationsthereof.

Covalent modification may include, but is not necessarily limited to,oxidation and subsequent chemical modification of oxidized secondnanoparticles, fluorination, free radical additions, addition ofcarbenes, nitrenes and other radicals, arylamine attachment viadiazonium chemistry, and the like. Besides covalent modification,chemical modification may occur by introducing noncovalentfunctionalization, electrostatic interactions, π-π interactions andpolymer interactions, such as wrapping a nanoparticle with a polymer,direct attachment of reactants to second nanoparticles by attacking thesp² bonds, direct attachment to ends of second nanoparticles or to theedges of the second nanoparticles, and the like.

It will be appreciated that the above methods are intended to illustratethe concept of functionally modifying the nanoparticles to introducefunctional groups to a second nanoparticle, and should not be consideredas limiting to such methods.

Prior to functional modification, the second nanoparticle may beexfoliated. Exemplary exfoliation methods include, but are notnecessarily limited to, those practiced in the art, including but notnecessarily limited to, fluorination, acid intercalation, acidintercalation followed by thermal shock treatment, and the like.Exfoliation of the graphene provides a graphene having fewer layers thannon-exfoliated graphene.

The effective medium theory states that properties of materials orfluids comprising different phases can be estimated from the knowledgeof the properties of the individual phases and their volumetric fractionin the mixture. In particular if a conducting particle is dispersed in adielectric fluid, the electrical conductivity of the dispersion willslowly increase for small additions of second nanoparticles. Aspetroleum coke and optional second nanoparticles are continually addedto the dispersion, the conductivity of the fluid increases, i.e. thereis a strong correlation between increased conductivity and increasedconcentration of petroleum coke and optional second nanoparticles. Ingeneral, this concentration is often referred to as the percolationlimit.

In the case of electrical conductivity, conductivity of nanofluids (i.e.dispersion of second nanoparticles in fluids), the percolation limitdecreases with decreasing the size of the second nanoparticles.Generally, this dependence of the percolation limit on the concentrationof the second nanoparticles holds for other fluid properties that dependon inter-particle average distance.

There is also a strong dependence on the shape of the secondnanoparticles dispersed within the phases for the percolation limit ofnano-dispersions. The percolation limit shifts further towards lowerconcentrations of the dispersed phase if the second nanoparticles havecharacteristic 2-D (platelets) or 1-D (nanotubes or nanorods)morphology. Thus the amount of 2-D or 1-D second nanoparticles necessaryto achieve a certain change in property is significantly smaller thanthe amount of 3-D second nanoparticles that would be required toaccomplish a similar effect.

In one sense, such fluids have made use of second nanoparticles for manyyears, since the clays commonly used in drilling fluids arenaturally-occurring, 1 nm thick discs of aluminosilicates. Such secondnanoparticles exhibit extraordinary rheological properties in water andoil. However, in contrast, the second nanoparticles that are the maintopic herein are synthetically formed second nanoparticles where size,shape and chemical composition are carefully controlled and give aparticular property or effect.

The fluids herein may contain petroleum coke, optional carbon black, andoptional second nanoparticles to improve the electrical conductivity ofthe fluids. In some cases, the second nanoparticles may change theproperties of the fluids in which they reside, based on various stimuliincluding, but not necessarily limited to, temperature, pressure,rheology, pH, chemical composition, salinity, and the like. This is dueto the fact that the second nanoparticles can be custom designed on anatomic level to have very specific functional groups, and thus thesecond nanoparticles react to a change in surroundings or conditions ina way that is beneficial. It should be understood that it is expectedthat second nanoparticles may have more than one type of functionalgroup, making them multifunctional. Multifunctional second nanoparticlesmay be useful for simultaneous applications, in a non-limiting exampleof a fluid, lubricating the drill bit, increasing the temperaturestability of the fluid, stabilizing the shale while drilling and providelow shear rate viscosity. In another non-restrictive embodiment, secondnanoparticles suitable for stabilizing shale include those having anelectric charge that permits them to associate with the shale.

Although the inventors do not wish to be bound to a particular theory,it is thought that capping the second nanoparticles, in a non-limitingembodiment, may decrease the oxygen reactivity of the secondnanoparticles by capping at least one oxygen species of the secondnanoparticles. In another non-limiting embodiment, the oxygen speciesthat may be capped include, but are not limited to carboxylic acids,ketones, lactones, anhydrides, hydroxyls, and combinations thereof. Thesecond nanoparticles may be functionalized nanoparticles ornon-functionalized nanoparticles prior to capping the secondnanoparticles. In some non-limiting embodiments, the secondnanoparticles may be functionally modified to form functionalizednanoparticles, and capping the functionalized second nanoparticles mayresult in a second nanoparticle having a semi-muted functionalization.Said differently, the second functionalized nanoparticle may stillmaintain some of the functionalized characteristics, but to a lesserextent than a fully functionalized second nanoparticle that has not beencapped. One skilled in the art would recognize when to cap or not cap afunctionalized or non-functionalized second nanoparticle.

The second nanoparticles may be capped by a method, such as but notlimited to, physical capping, chemical capping, and combinationsthereof. The second nanoparticles may or may not be functionallymodified prior to capping the second nanoparticles. A physical cappingmay occur by altering the ability of the oxygen species todecrease/eliminate electrostatic interactions, ionic interactions,physical absorption of the oxygen species, and the like. In non-limitingexamples, metal carbonyl species may be used to aid in physicallycapping the nanoparticles, such as but not limited to platinumcarbonyls, gold carbonyls, silver carbonyls, copper carbonyls, andcombinations thereof. In an alternative non-limiting embodiment, metalnanoparticles may be used for physically capping the secondnanoparticles, such as but not limited to platinum nanoparticles, goldnanoparticles, silver nanoparticles, copper nanoparticles, andcombinations thereof.

A chemical capping may occur by modifying chemical bonds of the secondnanoparticles to alter the oxygen reactivity of the nanoparticles,chemical absorption of the oxygen species, and the like. A non-limitingexample of a chemical capping may include altering the polarity of anoxygen species of the second nanoparticle to be a non-polar or lesspolar oxygen species. Other non-limiting examples of chemical cappingmay occur by performing a reaction with the oxygen species, such as butnot limited to a Grignard reaction, an alkyl esterification, anamidation, silanation with organic silanes, and combinations thereof.

In another non-limiting embodiment, the downhole fluid composition mayinclude a surfactant in an amount effective to suspend the petroleumcoke, optional carbon black, and optional second nanoparticles in thedownhole fluid. The surfactant may be present in the downhole fluidcomposition in an amount ranging from about 1 vol % independently toabout 10 vol %, or from about 2 vol % independently to about 8 vol % inanother non-limiting embodiment.

The use of optional surfactants together with the petroleum coke,optional carbon black, and optional second nanoparticles may formself-assembly structures that may enhance the thermodynamic, physical,and rheological properties of these types of fluids. The petroleum coke,optional carbon black, and optional second nanoparticles are dispersedin the oil-based fluid. The base fluid may be a non-aqueous fluid thatmay be a single-phase fluid or a poly-phase fluid, such as an emulsionof water-in-oil (W/O). The petroleum coke, optional carbon black, andoptional second nanoparticles may be used in conventional operations andchallenging operations that require stable fluids for high temperatureand pressure conditions (HTHP).

Expected suitable surfactants may include, but are not necessarilylimited to non-ionic, anionic, cationic, amphoteric surfactants andzwitterionic surfactants, janus surfactants, and blends thereof.Suitable nonionic surfactants may include, but are not necessarilylimited to, alkyl polyglycosides, sorbitan esters, methyl glucosideesters, amine ethoxylates, diamine ethoxylates, polyglycerol esters,alkyl ethoxylates, alcohols that have been polypropoxylated and/orpolyethoxylated or both. Suitable anionic surfactants may include alkalimetal alkyl sulfates, alkyl ether sulfonates, alkyl sulfonates, alkylaryl sulfonates, linear and branched alkyl ether sulfates andsulfonates, alcohol polypropoxylated sulfates, alcohol polyethoxylatedsulfates, alcohol polypropoxylated polyethoxylated sulfates, alkyldisulfonates, alkylaryl disulfonates, alkyl disulfates, alkylsulfosuccinates, alkyl ether sulfates, linear and branched ethersulfates, alkali metal carboxylates, fatty acid carboxylates, andphosphate esters. Suitable cationic surfactants may include, but are notnecessarily limited to, arginine methyl esters, alkanolamines andalkylenediamides. Suitable surfactants may also include surfactantscontaining a non-ionic spacer-arm central extension, and an ionic ornonionic polar group. Other suitable surfactants may be dimeric orgemini surfactants, cleavable surfactants, janus surfactants andextended surfactants, also called extended chain surfactants.

In one non-restrictive version, the average nanoparticle length for thesecond nanoparticles to aid the petroleum coke and optional carbon blackin improving the electrical conductivity properties may range from about1 nm independently to about 10,000 nm, alternatively from about 10 nmindependently to about 1000 nm. Enhanced electrical conductivity of thefluids may form an electrically conductive filter cake that highlyimproves real time high resolution logging processes, as compared withan otherwise identical fluid absent the petroleum coke and optionalsecond nanoparticles.

In one non-limiting embodiment, the downhole fluid composition mayinclude the oil-based fluid, and the petroleum coke; but in the absenceof the optional carbon black, the optional second nanoparticles and/orthe optional surfactant. The petroleum coke may be calcined petroleumcoke, green coke, and/or anode-grade coke as mentioned above. In anothernon-limiting embodiment, the downhole fluid composition may include theoil-based fluid, the petroleum coke, and an optional surfactant; but inthe absence of the optional carbon black, and the optional secondnanoparticles. Alternatively, the downhole fluid composition may includethe oil-based fluid, the petroleum coke, and optional secondnanoparticles that may be capped or not capped; but in the absence ofthe optional surfactant, and the optional carbon black. In yet anothernon-limiting embodiment, the downhole fluid composition may include theoil-based fluid, the petroleum coke, the optional surfactant, and theoptional second nanoparticles that may be capped or not capped; but inthe absence of the optional carbon black. In another alternativenon-limiting embodiment, the downhole fluid composition may include theoil-based fluid, the petroleum coke, the optional surfactant, theoptional second nanoparticles, and the optional carbon black(nanoparticle or not).

The downhole fluid composition may be circulated into a subterraneanreservoir wellbore where the downhole fluid comprises the oil-basedfluid, the petroleum coke, the optional surfactant, the optional carbonblack, and/or the optional second nanoparticles. A downhole tool may beoperated with the downhole fluid composition at the same time ordifferent time as the circulating of the downhole fluid. The downholetool may have or provide an improved image as compared to a downholetool being operated at the same time or different time as a downholefluid absent the petroleum coke.

Other benefits that may arise from modifying the electrical conductivityof the downhole fluids may include enabling the implementation ofmeasuring tools based on resistivity with superior image resolution, andimproving the ability of a driller to improve its efficiency in thenon-limiting instance of drilling fluids and/or completion fluids. Itmay also be conceivable that an electric signal may be able to becarried through the downhole fluids across longer distances, such asacross widely spaced electrodes in or around the bottom-hole assembly,or even from the bottom of the wellbore to intermediate stations or thesurface of the well.

The invention will be further described with respect to the followingExamples, which are not meant to limit the invention, but rather tofurther illustrate the various embodiments.

EXAMPLES Example 1

FIG. 1 is a graph illustrating the resistance measurements of twodifferent mineral oil formulations where each resistance measurementcorrelates to an amount of coke within each sample. Sample 1 had NPC15coke (supplied by Asbury Carbon), and Sample 2 had CC910 coke (suppliedby Oxbow Corporation). The amount of each type of coke within themineral oil is noted on the x-axis in FIG. 1. The mineral oil for sample1 and sample 2 was ESCAID 110™. As noted by the graph, Sample 1 had thelowest resistance regardless of the amount of coke within the sample.

Example 2

FIG. 2 is a graph illustrating the resistance measurements of fourdifferent mineral oil formulations where each formulation has adifferent type and/or amount of coke therein. Samples 1-4 appear left toright in FIG. 2. The mineral oil for Samples 1-4 is ESCAID 110™. Sample1 has no coke added thereto; Sample 2 had 6 wt % NPC15 added thereto;Sample 3 had 0.5 wt % of a carbon black (5303) added thereto; and Sample4 had 6 wt % NPC15 and 0.5 wt % carbon black added thereto. As noted inFIG. 2, Samples 2 and 3 had about the same resistivity measurements,which was about a decrease of three orders of magnitude as compared toSample 1. However, FIG. 4 had a decrease of about 4 orders of magnitudeas compared to Sample 1.

Example 3

FIG. 3 is a graph illustrating the resistance measurements of fourdifferent mineral oil formulations where each formulation has adifferent type and/or amount of coke therein. Samples 1-4 appear left toright in FIG. 3. The mineral oil for Samples 1-4 is ESCAID 110™. Sample1 has no coke added thereto; Sample 2 had 6 wt % CC910 added thereto;Sample 3 had 0.5 wt % of a carbon black added thereto; and Sample 4 had6 wt % CC910 and 0.5 wt % carbon black added thereto. As noted in FIG.2, Sample 2 and 3 had about the same resistivity measurements, which wasabout a decrease of three orders of magnitude as compared to Sample 1.However, Sample 4 had a decrease of about 4 orders of magnitude ascompared to Sample 1.

Example 4

A mud was formulated having 165 grams (g) of ESCAID 110™ mineral oil, 4g CARBO-GEL™, 12 g of a nonionic surfactant, 92 g of calcium chloridebrine, and 211 g MIL-BAR™. No coke was added to the formulation. Theoil/water ratio of the mud formulation was 75:25. The resistance wasmeasured at 1.2 E+6 Ohm @1 k Hz.

Example 5

A mud was formulated having 20 ppb CC910 coke material, 165 grams (g) ofESCAID 110™ mineral oil, 4 g CARBO-GEL™, 12 g of a nonionic surfactant,92 g of calcium chloride brine, 211 g MIL-BAR™, and 20 g of calcinatedcoke. The oil/water ratio of the mud formulation was 75:25. Theresistance was measured at 1.7E+4 Ohm @1 k Hz. 2 g of carbon black wasthen added to the mud formulation, and the resistance was measured asecond time at 6.2E+3 Ohm @1 k Hz.

Example 6

A mud was formulated having 20 ppb NPC15 coke material, 165 grams (g) ofESCAID 110™ mineral oil, 4 g CARBO-GEL™, 12 g of a nonionic surfactant,92 g of calcium chloride brine, 211 g MIL-BAR™, and 20 g of calcinatedcoke. The oil/water ratio of the mud formulation was 75:25. Theresistance was measured at 2.7E+4 Ohm @1 k Hz @1 k Hz. 1 g of carbonblack was then added to the mud formulation, and the resistance wasmeasured a second time at 2.2E+3 Ohm @1 k Hz.

The resistance of the mineral oil formulations in Examples 1-6 weremeasured by an impedance meter under the same conditions at 1 k Hz androom temperature. The coke material showed a dose-dependent responsethat correlated to the resistance measurements.

In the foregoing specification, the invention has been described withreference to specific embodiments thereof, and has been suggested aseffective in providing effective downhole fluid compositions and methodsfor improving the electrical conductivity of a downhole fluidcomposition. However, it will be evident that various modifications andchanges may be made thereto without departing from the broader spirit orscope of the invention as set forth in the appended claims. Accordingly,the specification is to be regarded in an illustrative rather than arestrictive sense. For example, specific combinations of componentsand/or reaction conditions for forming the petroleum coke and/or thesecond nanoparticles, whether modified to have particular shapes orcertain functional groups thereon, but not specifically identified ortried in a particular oil-based fluid to improve the properties therein,are anticipated to be within the scope of this invention.

The present invention may suitably comprise, consist or consistessentially of the elements disclosed and may be practiced in theabsence of an element not disclosed. For instance, the downhole fluidcomposition may consist of or consist essentially of an oil-based fluidand at least one petroleum coke in particle form; the oil-based fluidmay be or include a drilling fluid, a completion fluid, a drill-influid, a stimulation fluid, a servicing fluid, and combinations thereof.The amount of the at least one petroleum coke is effective to improvethe electrical conductivity of the downhole fluid.

The method may consist of or consist essentially of circulating adownhole fluid composition into a subterranean reservoir wellbore wherethe downhole fluid composition may be or include an oil-based fluid,such as drilling fluid, a completion fluid, a drill-in fluid, astimulation fluid, a servicing fluid, and combinations thereof; thedownhole fluid composition may include at least one petroleum coke in aneffective amount to improve the electrical conductivity of the downholefluid, and the at least one petroleum coke is in particle form.

The words “comprising” and “comprises” as used throughout the claims isto be interpreted as meaning “including but not limited to”.

What is claimed is:
 1. A downhole fluid composition comprising: anoil-based fluid; and at least one petroleum coke in particle form in anamount effective to improve the electrical conductivity of the downholefluid as compared to an otherwise identical fluid absent the at leastone petroleum coke.
 2. The downhole fluid composition of claim 1,wherein the at least one petroleum coke is calcined petroleum coke. 3.The downhole fluid composition of claim 1, wherein the at least onepetroleum coke is selected from the group consisting of a calcinedpetroleum coke, a green coke, an anode-grade coke, a coke treated with ametallic salt, and combinations thereof.
 4. The downhole fluidcomposition of claim 1, wherein the amount of the at least one petroleumcoke ranges from about 0.05 wt % to about 25 wt % based on the totalfluid composition.
 5. The downhole fluid composition of claim 1, whereinthe at least one petroleum coke has been treated with a metallic saltselected from the group consisting of metal halides, metal nitrites,metal sulfates, metal oxides, quaternary ammonium salts, metal nitrates,metal sulfonates, and combinations thereof.
 6. The downhole fluidcomposition of claim 1, wherein the size of the at least one petroleumcoke particles ranges from about 10 nm to about 1,000 microns.
 7. Thedownhole fluid composition of claim 1, further comprising a surfactantin an amount effective to suspend the at least one petroleum coke in theoil-based fluid.
 8. The downhole fluid composition of claim 1, furthercomprising particles selected from the group consisting of carbon blackparticles, second nanoparticles, and combinations thereof.
 9. A downholefluid composition comprising: an oil-based fluid; at least one petroleumcoke in particle form in an amount ranging from about 0.05 wt % to about25 wt %; and a surfactant in an effective amount to suspend the at leastone petroleum coke in the oil-based fluid.
 10. A method comprising:circulating a downhole fluid composition into a subterranean reservoirwellbore; wherein the downhole fluid composition comprises an oil-basedfluid; and wherein the downhole fluid composition comprises at least onepetroleum coke in an effective amount to improve the electricalconductivity of the downhole fluid, and the at least one petroleum cokeis in particle form.
 11. The method of claim 10, further comprisingadding the at least one petroleum coke to the oil-based fluid prior tocirculating the downhole fluid composition.
 12. The method of claim 10,further comprising operating a downhole tool at the same time ordifferent time as circulating the downhole fluid composition.
 13. Themethod of claim 10, wherein the at least one petroleum coke is calcinedpetroleum coke.
 14. The method of claim 10, wherein the at least onepetroleum coke is selected from the group consisting of calcinedpetroleum coke, green coke, an anode-grade coke, a coke treated with ametallic salt, and combinations thereof.
 15. The method of claim 10,wherein the amount of the at least one petroleum coke ranges from about0.05 wt % to about 25 wt % based on the total fluid composition.
 16. Themethod of claim 10, wherein the at least one petroleum coke has beentreated with a metallic salt selected from the group consisting of metalhalides, metal nitrites, metal sulfates, metal oxides, quaternaryammonium salts, metal nitrates, metal sulfonates, and combinationsthereof.
 17. The method of claim 10, wherein the size of the at leastone petroleum coke particles ranges from about 10 nm to about 1,000microns.
 18. The method of claim 10, further comprising particlesselected from the group consisting of carbon black particles, secondnanoparticles, and combinations thereof.
 19. The method of claim 10where the downhole fluid composition is made by a process comprising inany order: adding an effective amount of at least one petroleum coke inparticle form to an oil-based fluid to form a downhole fluid compositionhaving improved electrical conductivity; wherein he at least onepetroleum coke is in particle form; and adding at least one surfactantto the oil-based fluid in an amount effective to suspend the at leastone petroleum coke in the oil-based fluid.